Apparent dip angle calculation and image compression based on region of interest

ABSTRACT

The present invention provides a method and apparatus for logging an earth formation and acquiring subsurface information wherein a logging tool is conveyed in borehole to obtain parameters of interest. The parameters of interest obtained may be density, acoustic, magnetic or electrical values as known in the art. The parameters of interest may be transmitted to the surface at a plurality of resolutions using a multi-resolution image compression method. Parameters of interest are formed into a plurality of Cost Functions from which Regions of Interest are determined to resolve characteristics of the Features of interest within the Regions. Feature characteristics may be determined to obtain time or depth positions of bed boundaries and borehole Dip Angle relative to subsurface structures, as well borehole and subsurface structure orientation. Characteristics of the Features include time, depth, and geometries of the subsurface such as structural dip, thickness, and lithologies.

CROSS REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part of U.S. patent applicationSer. No. 10/892,011 filed Jul. 15, 2004 now U.S. Pat. No. 7,200,492.

FIELD OF THE INVENTION

This invention relates generally to borehole logging apparatus for useduring drilling operations and methods for acquiring subsurfacemeasurements and communicating the data to the surface. Moreparticularly, this invention relates to subsurface featureidentification and efficient transmission of imaging data and subsurfacestructure data in real time in a measurement-while-drilling (MWD) tool.

BACKGROUND OF THE ART

Oil well logging has been known for many years and provides an oil andgas well driller with information about the particular earth formationbeing drilled. In conventional oil well logging, after a well has beendrilled, a probe known as a sonde is lowered into the borehole and usedto determine some characteristic of the formations which the well hastraversed. The probe is typically a hermetically sealed steel cylinderwhich hangs at the end of a long cable which gives mechanical support tothe sonde and provides power to the instrumentation inside the sonde.The cable also provides communication channels for sending informationup to the surface. It thus becomes possible to measure some parameter ofthe earth's formations as a function of depth, that is, while the sondeis being pulled uphole. Such “wireline” measurements are normally donein real time (however, these measurements are taken long after theactual drilling has taken place).

A wireline sonde usually transmits energy into the formation as well asa suitable receiver for detecting the same energy returning from theformation to provide acquisition of a parameter of interest. As is wellknown in this art, these parameters of interest include electricalresistivity, acoustic energy, or nuclear measurements which directly orindirectly give information on subsurface densities, reflectances,boundaries, fluids and lithologies among many others.

Examples of prior art wireline density devices are disclosed in U.S.Pat. Nos. 3,202,822, 3,321,625, 3,846,631, 3,858,037, 3,864,569 and4,628,202. Wireline formation evaluation tools (such as gamma raydensity tools) have many drawbacks and disadvantages including loss ofdrilling time, the expense and delay involved in tripping thedrillstring so as to enable the wireline to be lowered into the boreholeand both the build up of a substantial mud cake and invasion of theformation by the drilling fluids during the time period between drillingand taking measurements. An improvement over these prior art techniquesis the art of measurement-while-drilling (MWD) in which many of thecharacteristics of the formation are determined substantiallycontemporaneously with the drilling of the borehole.

Measurement-while-drilling (MWD) logging either partly or totallyeliminates the necessity of interrupting the drilling operation toremove the drillstring from the hole in order to make the necessarymeasurements obtainable by wireline techniques. In addition to theability to log the characteristics of the formation through which thedrill bit is passing, this information on a real time basis providessubstantial safety and logistical advantages for the drilling operation.

One potential problem with MWD logging tools is that the measurementsare typically made while the tool is rotating. Since the measurementsare made shortly after the drillbit has drilled the borehole, washoutsare less of a problem than in wireline logging. Nevertheless, there canbe some variations in the spacing between the logging tool and theborehole wall (“standoff”) with azimuth. Nuclear measurements areparticularly degraded by large standoffs due to the scattering producedby borehole fluids between the tool and the formation.

U.S. Pat. No. 5,397,893 to Minette, the contents of which are fullyincorporated herein by reference, teaches a method for analyzing datafrom a MWD formation evaluation logging tool which compensates forrotation of the logging tool (along with the rest of the drillstring)during measurement periods. The density measurement is combined with themeasurement from a borehole caliper, preferably an acoustic caliper. Theacoustic caliper continuously measures the standoff as the tool isrotating around the borehole. If the caliper is aligned with the densitysource and detectors, this gives a determination of the standoff infront of the detectors at any given time. This information is used toseparate the density data into a number of bins based on the amount ofstandoff. After a pre-set time interval, the density measurement canthen be made. The first step in this process is for short space (SS) andlong space (LS) densities to be calculated from the data in each bin.Then, these density measurements are combined in a manner that minimizesthe total error in the density calculation. This correction is appliedusing the “spine and ribs” algorithm and graphs such as that shown inFIG. 1. In the figure, the abscissa 1 is the difference between the LSand SS densities while the ordinate 3 is the correction that is appliedto the LS density to give a corrected density using the curve 5.

U.S. Pat. No. 5,513,528 to Holenka et al teaches a method and apparatusfor measuring formation characteristics as a function of azimuth aboutthe borehole. The measurement apparatus includes a logging whiledrilling tool which turns in the borehole while drilling. The downvector of the tool is derived first by determining an angle φ between avector to the earth's north magnetic pole, as referenced to the crosssectional plane of a measuring while drilling (MWD) tool and a gravitydown vector as referenced in the plane. The logging while drilling (LWD)tool includes magnetometers and accelerometers placed orthogonally in across-sectional plane. Using the magnetometers and/or accelerometermeasurements, the toolface angle can usually be determined. The angle φis transmitted to the LWD tool thereby allowing a continuousdetermination of the gravity down position in the LWD tool. Quadrants,that is, angular distance segments, are measured from the down vector.Referring to FIG. 2 (which is Holenka et al's FIG. 10B illustrating aLWD tool 100 rotating in an inclined borehole 12), an assumption is madethat the down vector defines a situation in which the standoff is at aminimum, allowing for a good spine and rib correction. A drawback of theHolenka et al method is that the assumption of minimum standoff is notnecessarily satisfied, so that the down position may in fact correspondto a significant standoff; without a standoff correction the results maybe erroneous.

In a centralized or stabilized tool, the standoff will generally beuniform with azimuth. Holenka (U.S. Pat. No. 5,513,528) and Edwards(U.S. Pat. No. 6,307,199) also show how azimuthal measurements ofdensity may be diagnostic of bed boundaries intersected by an inclinedborehole. In the absence of standoff corrections, this can only be aqualitative measurement.

U.S. Pat. No. 6,584,837 to Kurkoski, fully incorporated by referenceherein, discloses a LWD density sensor that includes a gamma ray sourceand at least two NaI detectors spaced apart from the source fordetermining measurements indicative of the formation density. Amagnetometer on the drill collar measures the relative azimuth of theNaI detectors. An acoustic caliper is used for making standoffmeasurements of the NaI detectors. Measurements made by the detectorsare partitioned into spatial bins defined by standoff and azimuth.Within each azimuthal sector, the density measurements are compensatedfor standoff to provide a single density measurement for the sector. Theazimuthal sectors are combined in such a way as to provide a compensatedazimuthal geosteering density. The method of the invention may also beused with neutron porosity logging devices.

MWD instruments, in some cases, include a provision for sending at leastsome of the subsurface images and measurements acquired to recordingequipment at the earth's surface at the time the measurements are madeusing a telemetry system (i.e. MWD telemetry). One such telemetry systemmodulates the pressure of a drilling fluid pumped through the drillingassembly to drill the wellbore. The fluid pressure modulation telemetrysystems known in the art, however, are limited to transmitting data at arate of at most only a few bits per second. Because the volume of datameasured by the typical image-generating well logging instrument isrelatively large, at present, borehole images are generally availableonly using electrical cable-conveyed instruments, or after an MWDinstrument is removed from the wellbore and the contents of an internalstorage device, or memory, are retrieved.

Many types of well logging instruments have been adapted to makemeasurements which can be converted into a visual representation or“image” of the wall of a wellbore drilled through earth formations.Typical instruments for developing images of parameters of interestmeasurements include density measuring devices, electrical resistivitymeasuring devices and acoustic reflectance/travel time measuringdevices. These instruments measure a property of the earth formationsproximate to the wall of the wellbore, or a related property, withrespect to azimuthal direction, about a substantial portion of thecircumference of the wellbore. The values of the property measured arecorrelated to both their depth position in the wellbore and to theirazimuthal position with respect to some selected reference, such asgeographic north or the gravitationally uppermost side of the wellbore.A visual representation is then developed by presenting the values, withrespect to their depths and azimuthal orientations, for instance, usinga color or gray tone which corresponds to the value of the measuredproperty.

One method known in the art for transmitting image-generatingmeasurements in pressure modulation telemetry is described, for example,in U.S. Pat. No. 5,519,668 issued to Montaron. This method includesmaking resistivity measurements at preselected azimuthal orientations,and transmitting the acquired resistivity values to the surface throughthe pressure modulation telemetry. The method described in the Montaron'668 patent requires synchronization of the resistivity measurements toknown rotary orientations of the MWD instrument to be able to decode theimage data at the surface without transmitting the corresponding rotaryorientations at which the measurements were made.

U.S. Pat. No. 6,405,136 to Li, et al fully incorporated by referenceherein, discloses a method for compressing a frame of data representingparameter values, a time at which each parameter value was recorded, andan orientation of a sensor at the time each parameter value wasrecorded. Generally the method includes performing a two-dimensionaltransform on the data in the orientation domain and in a domain relatedto the recording time. In one embodiment, the method includescalculating a logarithm of each parameter value. In one embodiment, the2-D transform includes generating a Fourier transform of the logarithmof the parameter values in the azimuthal domain, generating a discretecosine transform of the transform coefficients in the time domain. Thisembodiment includes quantizing the coefficients of the Fourier transformand the discrete cosine transform. One embodiment of the method isadapted to transmit resistivity measurements made by an LWD instrumentin pressure modulation telemetry so that while-drilling images of awellbore can be generated. The one embodiment includes encoding thequantized coefficients, error encoding the encoded coefficients, andapplying the error encoded coefficients to the pressure modulationtelemetry.

Other data compression techniques, for various applications, aredescribed in several other U.S. patents, for example, U.S. Pat. No.5,757,852 to Jericevic et al; U.S. Pat. No. 5,684,693 to Li; U.S. Pat.No. 5,191,548 to Balkanski et al; U.S. Pat. No. 5,301,205 to Tsutsui etal; U.S. Pat. No. 5,388,209 to Akagiri; U.S. Pat. No. 5,453,844 toGeorge et al; U.S. Pat. No. 5,610,657 to Zhang; and U.S. Pat. No.6,049,632 to Cockshott et al. Many prior art data compression techniquesare not easily or efficiently applicable to the extremely low bandwidthand very high noise level of the communication methods of the typicalMWD pressure modulation telemetry system, and, have not been suitablefor image transmission by such telemetry.

U.S. application Ser. No. 10/167,332 (Publication 20020195276 A1) toDubinsky et al, entitled “Use of Axial Accelerometer for Estimation ofInstantaneous ROP Downhole for Lwd and Wireline Applications” thecontents of which are incorporated herein by reference, disclose thatdetermination of the rate of penetration (ROP) of drilling has usuallybeen based upon surface measurements and may not be an accuraterepresentation of the actual ROP. This can cause problems in LoggingWhile Drilling (LWD). Because of the lack of a high-speedsurface-to-downhole communication while drilling, a conventional methodof measuring ROP at the surface does not provide a solution to thisproblem. However, the instantaneous ROP can be derived downhole with acertain degree of accuracy by utilizing an accelerometer placed in (ornear) the tool to measure acceleration in the axial direction. Whenthree-component accelerometers are used, the method may be used todetermine the true vertical depth of the borehole.

There is a need for a method of determining subsurface features indownhole logging data, for example with azimuthal density variationsfrom measurements made by a MWD logging tool. Such a method preferablyprovides for real-time determination of down hole parameter forcommunication to the surface, or provides for real time imaging of thesubsurface environment during drilling operations. The present inventionsatisfies this need. It is desirable to have a system which enablestransmission of data for imaging a wellbore through pressure modulationor other telemetry so that images of a wellbore can be developed duringthe drilling of a wellbore, wherein the rotary orientation of eachimage-developing measurement is included in the transmitted data. It isalso desirable to efficiently and timely determine estimates ofpositions and orientations of boundaries between layers of earthformations.

SUMMARY OF THE INVENTION

The present invention provides a method and apparatus for logging anearth formation and acquiring subsurface information wherein a loggingtool is conveyed in a borehole to obtain parameters of interest. Theparameters of interest obtained may be density, acoustic, magnetic orelectrical values as known in the art. As necessary, an azimuthassociated with the parameters of interest measurements are obtained andcorrections applied. The corrected data may be filtered and/or smoothed.The parameters of interest associated with azimuthal sectors are formedinto a plurality of Cost Functions from which Regions of Interest aredetermined to resolve characteristics of the Features of interest withinthe Regions of Interest. Also, for initial delineation of Regions ofInterest and associated Features, Cost Functions from a plurality ofsectors may be combined to efficiently obtain prospective areas of theCost Functions. Characteristics of these Features may be determined toobtain time or depth positions of bed boundaries and the Dip Angle ofthe borehole relative to subsurface structures, as well as theorientation of the logging equipment (borehole) and subsurfacestructure. Characteristics of the Features include time, depth,lithologies, structural depths, dip and thicknesses. The Regions ofInterest may be generally characterized according to the behavior of theRegions in the neighborhood of various subsurface features. For example,a thin-bed type response may be characterized where the Region ofInterest spans two local maxima with a local minimum between the maxima.There are at least four types of features (i.e. features of interest)that may be identified and/or extracted from Regions of Interest.

BRIEF DESCRIPTION OF THE FIGURES

The present invention and its advantages will be better understood byreferring to the following detailed description and the attacheddrawings in which:

FIG. 1 (PRIOR ART) shows an example of how density measurements madefrom a long spaced and a short spaced tool are combined to give acorrected density;

FIG. 2 (PRIOR ART) shows an idealized situation in which a rotating toolin a wellbore has a minimum standoff when the tool is at the bottom ofthe wellbore;

FIG. 3 shows a schematic diagram of a drilling system having a drillstring that includes an apparatus according to the present invention;

FIG. 4 illustrates a flow chart of the present invention;

FIG. 5A illustrates raw density data with a Region of Interest;

FIG. 5B illustrates a cost function display of obtained data with aRegion of Interest and a Feature in the Region of Interest;

FIG. 5C illustrates types of Features that may be associated with aRegion of Interest;

FIG. 6A illustrates a function that represents the Dip Angle relative tothe well bore;

FIG. 6B illustrates the relationship of Regions of Interest withFeatures and Dip Angle among the several azimuthal sectors, and showsboth raw and smoothed (filtered) data;

FIG. 7 illustrates an estimate of data size sample versus DC value forthe Discrete Cosine Transform;

FIG. 8 illustrates a data scanning method according to the EmbeddedZerotree Wavelet Encoder;

FIG. 9 illustrates raw density data across 8 sectors;

FIG. 10 illustrates an uncompressed image reconstructed using thepresent invention with a compression of 300:1;

FIG. 11 illustrates an uncompressed image reconstructed using thepresent invention with a compression of 150:1;

FIG. 12 illustrates an uncompressed image reconstructed using thepresent invention with a compression of 100:1;

FIG. 13 illustrates the acc error versus the compression ratio;

FIG. 14 illustrates the Root-mean-square (RMS) error versus thecompression ratio;

FIG. 15 is a flow chart of an embodiment of the present invention;

FIG. 16 is a flow chart of an embodiment of the present invention; and

FIG. 17 is a flow chart of an embodiment of the present invention.

While the invention will be described in connection with its preferredembodiments, it will be understood that the invention is not limitedthereto. It is intended to cover all alternatives, modifications, andequivalents which may be included within the spirit and scope of theinvention, as defined by the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 3 shows a schematic diagram of a drilling system 110 having adownhole assembly containing an acoustic sensor system and the surfacedevices according to one embodiment of present invention. As shown, thesystem 110 includes a conventional derrick 111 erected on a derrickfloor 112 which supports a rotary table 114 that is rotated by a primemover (not shown) at a desired rotational speed. A drill string 120 thatincludes a drill pipe section 122 extends downward from the rotary table114 into a borehole 126. A drill bit 150 attached to the drill stringdownhole end disintegrates the geological formations when it is rotated.The drill string 120 is coupled to a drawworks 130 via a kelly joint121, swivel 118 and line 129 through a system of pulleys 127. During thedrilling operations, the drawworks 130 is operated to control the weighton bit and the rate of penetration of the drill string 120 into theborehole 126. The operation of the drawworks is well known in the artand is thus not described in detail herein.

During drilling operations a suitable drilling fluid (commonly referredto in the art as “mud”) 131 from a mud pit 132 is circulated underpressure through the drill string 120 by a mud pump 134. The drillingfluid 131 passes from the mud pump 134 into the drill string 120 via adesurger 136, fluid line 138 and the kelly joint 121. The drilling fluidis discharged at the borehole bottom 151 through an opening in the drillbit 150. The drilling fluid circulates uphole through the annular space127 between the drill string 120 and the borehole 126 and is dischargedinto the mud pit 132 via a return line 135. Preferably, a variety ofsensors (not shown) are appropriately deployed on the surface accordingto known methods in the art to provide information about variousdrilling-related parameters, such as fluid flow rate, weight on bit,hook load, etc.

A surface control unit 140 receives signals from the downhole sensorsand devices via a sensor 143 placed in the fluid line 138 and processessuch signals according to programmed instructions provided to thesurface control unit. The surface control unit displays desired drillingparameters and other information on a display/monitor 142 whichinformation is utilized by an operator to control the drillingoperations. The surface control unit 140 contains a computer, memory forstoring data, data recorder and other peripherals. The surface controlunit 140 also includes models and processes data according to programmedinstructions and responds to user commands entered through a suitablemeans, such as a keyboard. The control unit 140 is preferably adapted toactivate alarms 144 when certain unsafe or undesirable operatingconditions occur.

A drill motor or mud motor 155 coupled to the drill bit 150 via a driveshaft (not shown) disposed in a bearing assembly 157 rotates the drillbit 150 when the drilling fluid 131 is passed through the mud motor 155under pressure. The bearing assembly 157 supports the radial and axialforces of the drill bit, the downthrust of the drill motor and thereactive upward loading from the applied weight on bit. A stabilizer 158coupled to the bearing assembly 157 acts as a centralizer for thelowermost portion of the mud motor assembly.

In the preferred embodiment of the system of present invention, thedownhole subassembly 159 (also referred to as the bottomhole assembly or“BHA”) which contains the various sensors and MWD devices to provideinformation about the formation and downhole drilling parameters and themud motor, is coupled between the drill bit 150 and the drill pipe 122.The downhole assembly 159 preferably is modular in construction, in thatthe various devices are interconnected sections so that the individualsections may be replaced when desired.

Still referring back to FIG. 3, the BHA also preferably contains sensorsand devices in addition to the above-described sensors. Such devicesinclude a device for measuring the formation resistivity near and/or infront of the drill bit, a gamma ray device for measuring the formationgamma ray intensity and devices for determining the inclination andazimuth of the drill string. The formation resistivity measuring device164 is preferably coupled above the lower kick-off subassembly 162 thatprovides signals, from which resistivity of the formation near or infront of the drill bit 150 is determined. A dual propagation resistivitydevice (“DPR”) having one or more pairs of transmitting antennae 166 aand 166 b spaced from one or more pairs of receiving antennae 168 a and168 b is used. Magnetic dipoles are employed which operate in the mediumfrequency and lower high frequency spectrum. In operation, thetransmitted electromagnetic waves are perturbed as they propagatethrough the formation surrounding the resistivity device 164. Thereceiving antennae 168 a and 168 b detect the perturbed waves. Formationresistivity is derived from the phase and amplitude of the detectedsignals. The detected signals are processed by a downhole circuit thatis preferably placed in a housing 170 above the mud motor 155 andtransmitted to the surface control unit 140 using a suitable telemetrysystem 172. In addition to or instead of the propagation resistivitydevice, a suitable induction logging device may be used to measureformation resistivity.

The inclinometer 174 and gamma ray device 176 are suitably placed alongthe resistivity measuring device 164 for respectively determining theinclination of the portion of the drill string near the drill bit 150and the formation gamma ray intensity. Any suitable inclinometer andgamma ray device, however, may be utilized for the purposes of thisinvention. In addition, an azimuth device (not shown), such as amagnetometer or a gyroscopic device, may be utilized to determine thedrill string azimuth. Such devices are known in the art and are, thus,not described in detail herein. In the above-described configuration,the mud motor 155 transfers power to the drill bit 150 via one or morehollow shafts that run through the resistivity measuring device 164. Thehollow shaft enables the drilling fluid to pass from the mud motor 155to the drill bit 150. In an alternate embodiment of the drill string120, the mud motor 155 may be coupled below resistivity measuring device164 or at any other suitable place.

The drill string contains a modular sensor assembly, a motor assemblyand kick-off subs. In a preferred embodiment, the sensor assemblyincludes a resistivity device, gamma ray device and inclinometer, all ofwhich are in a common housing between the drill bit and the mud motor.The downhole assembly of the present invention preferably includes a MWDsection 168 which contains a nuclear formation porosity measuringdevice, a nuclear density device, an acoustic sensor system placed, anda formation testing system above the mud motor 164 in the housing 178for providing information useful for evaluating and testing subsurfaceformations along borehole 126. A downhole processor may be used forprocessing the data.

Wireline logging tools have been used successfully to produce subsurfaceimages. For MWD applications, density tool measurements and othermeasurements have been stored in the MWD tool's memory. Thereforesubsurface images and parameter determinations haven't been generallyavailable for real time applications such as geosteering.

The present invention which provides for acquiring parameters ofinterest is discussed with reference to a density measurement tool thatemits nuclear energy, and more particularly gamma rays, but the methodof the present invention is applicable to other types of logginginstruments as well (e.g., acoustic methods, magnetic resonance andelectrical methods). Wireline gamma ray density probes are well knownand comprise devices incorporating a gamma ray source and a gamma raydetector, shielded from each other to prevent counting of radiationemitted directly from the source. During operation of the probe, gammarays (or photons) emitted from the source enter the formation to bestudied, and interact with the atomic electrons of the material of theformation by photoelectric absorption, by Compton scattering, or by pairproduction. In photoelectric absorption and pair production phenomena,the particular photons involved in the interacting are removed from thegamma ray beam. Instruments for making measurements of acousticproperties and gamma-gamma density have several advantages known in theart, and it should be understood that the instruments disclosed are notthe only instruments that can be used to make such measurements.Accordingly, the invention is not to be limited to measurements ofparameters of interest made by the particular instruments describedherein.

The present invention provides for subsurface feature extraction, datacompression, dip angle calculation, and semi-real-time data transmissionto the surface. Transmission of raw or reduced subsurface data in nearreal-time to the surface provides for calculation of subsurfacestructure dip angles in semi or near real time for geosteering. Theinvention may be implemented in firmware and/or software downhole. Forexample, the invention provides for receiving the acquired subsurfacedata divided into sectors (eight, for example), the data are compressed,the apparent dip may be calculated, the data and/or the calculations maybe transmitted to the surface and uncompressed for display. For examplea formation bed boundary may display as a sine wave. An example productis a downhole apparatus with a processor with software that receivesdensity data which may be divided into sectors (for example in eightsectors), compresses the data, calculates the apparent dip angle,formats the data for transmission, uncompresses the data at the surfaceand formats the data for further uses.

The compression algorithm and apparent dip angle calculation are basedon feature extraction concepts. The present invention provides animplementation in three modules: i) compression, ii) reconstruction andiii) display.

The compression module receives data (which may be formatted in blocks)of the density for the standoff sectors, for example eight sectors,along with an optional set of parameters which may be selected frompredefined parameters to customize the compression according to userneed and a priori knowledge of the downhole environment. This moduleruns downhole to compress the image, code the image, calculate theparameters of the dip angle, code the parameters of the dip angle,format the data and transmit the data to the telemetry.

FIG. 4 illustrates a block diagram. Raw data 401 along with selectedparameters 403 goes into the Preprocessing Module 405. The PreprocessingModule 405 ensures that data values are in expected ranges, for exampledensity is in the range from 1.5 gm/cc to 3 gm/cc. In the case where thedensity data has a value outside this range, the preprocessing moduleeither interpolates the data or generates a segmentation based on thenumber of invalid or null data points. The preprocessing module receivesboth the data and the compression parameters from the memory module,which may be flash memory. The parameters may be preset or supplied bydownlink.

The preprocessing module 405 performs three separate tasks. The firsttask is to get the parameters of the algorithm. Based on the downlink orpreset parameters, the parameters are set in memory. The algorithm thenpasses the parameters to the data collection procedure. A flash memorymodule is one way that parameters and instructions may be stored andprovided for the present invention.

The second task is data collection. Based on the parameters for thecompression, pointers are going to be generated to point to the start ofeach data block that needs to be processed and the block lengths.

Third task is to check the density data values. In some cases densitydata values appear in the memory as a null value for many reasons. Thepreprocessing module 405 applies the following strategy on the nullvalue: If the number of reading that contains a null value is less thanor equal to a selected value, an interpolation is made. If the number ofthe null data that contains a null value is more than the selectedvalue, the image is divided into two parts, which is calledsegmentation.

The Feature Extraction Module 407 runs if it has been chosen or enabled(for example in the flash memory parameters). The feature extractionmodule generates a cost function based on both the direction of thechange and the change in the value of the parameter of interest (e.g.,density data). Any maximum or minimum of that cost function, orvariations of maxima and minima, indicates the possible locations of bedboundaries, i.e. the possibility of a feature. The region between thelocation of the two zeros around the maximum or the minimum that resultsfrom the first derivative of that cost function represents a region ofinterest i.e. the region that likely contains one or more features ofinterest. The block of data or number of samples within a cost functionmay be set arbitrarily. If the absolute value of the last value of thecost function is close to zero, it means that there are no features thatshare the current block of data and the next block of data. If theabsolute value of the cost function value is close to or greater thanone, it means that there are feature/features shared between/among thecurrent block of data and the next block of data. The distance betweenthe location of the last zero of the first derivative of the costfunction and the end of the current data block determine an overlapregion. The overlap region will be added to the next adjacent block ofdata. This guarantees that the next block of data will contain acomplete feature.

FIG. 5A illustrates raw data containing features of interest. FIG. 5Billustrates the Cost Function, including the Feature location and aRegion of Interest. This feature could be a “thin bed” or othersubsurface structure or bedding boundary.

Extracting the Feature characteristics from within the Cost Function isaccomplished by examination and comparison of the behavior of theexcursions of the waveform (or data trace) in relation to a chosenreference or in relation to localized changes in the Cost Function. Asillustrated in FIG. 5B, the Cost Function is analyzed to discoverparameters that satisfy all chosen constraints, and produce an optimumvalue for determining features of interest in the Cost Function. TheCost Function examination optimally works out how to adjust the designvariables for subsequent runs. This produces an optimized design forefficient Feature identification and extraction. In the example shownhere, the Region of Interest spans a waveform section of parametervalues that is the area between and including two local maxima. Theselocal maxima bracket a local minimum, which minimum coincides with theposition of a Feature. Suitable wavelet functions may be chosen todeconvolve the Feature efficiently to delineate these maxima and minimain order obtain feature positions in terms of time, depth, dip angle orother characteristics.

While FIG. 5B illustrates a Region of Interest spanning local minima,there are three other features of interest that may be found in andaround a Region of Interest, which Features are illustrated in FIG. 5Crelative to an arbitrary reference 509 demarking relative positive fromrelative negative values for purposes of illustration. Parameters ofinterest such as density may all be obtained as positive values, so itis the local variations that vary around an arbitrary reference. Inaddition to the local minima 501, other Feature types include localmaxima 503, a transition from a local maximum to a local minimum 505,and a transition from a local minimum to a local maximum 507. A localmaxima feature 503 could represent a low density thin bed; a localminimum 501 can represent a high density thin bed. Whether a bed istermed ‘thin’ or not, of course, is relative to both bed size and/orsample interval. An example of transition from local maximum to localminimum 505 is a step decrease in a density reading. An example oftransition from local minimum to local maximum 507 is a step increase ina density reading. There are many choices for wavelets that may be usedto efficiently identify Features within Regions of Interest.

Calculation of the Apparent Dip Angle: Dip Angle calculation isillustrated at 419 in FIG. 4. Because a plane intersects a well bore asa periodic function, fitting a suitable mathematical function, forexample a transcendental or a wavelet function, to the Feature positiondata as illustrated in FIG. 6A is straightforward (e.g., a DiscreteCosine Transform). FIG. 6A illustrates a function that represents theDip Angle 601 relative to the well bore across several sectors. The dipangle function 601 along the sections of the well bore conforms to theFeature positions that have been determined from the analysis of theCost Function. The Cost Function as illustrated in FIG. 6B acrossmultiple azimuthal sectors indicates the location of the Region ofInterest where a Feature exists along the Dip Angle 601. If the costfunction has a minimum value it means that the density data has beendecreasing and we will look for a local minimum value in the Region ofInterest. If the cost function has a maximum value it means that thedensity data has been increased and we will look for a maximum withinthe Region of Interest (for example a Feature such as 501 in FIGS. 5Band 5C).

FIG. 6B illustrates a smoothed version of the data with the region ofinterest generated for each sector. The direction of change of the totaldensity data may be examined in the eight sectors in both the Raw Dataand the same eight sectors of the Smooth Data smoothed version for theraw data with the region of interest. For a decision to be made inpreprocessing (e.g. FIG. 4 preprocessing 405) that there is a feature ofinterest in a specific location, the following parameters are anon-exclusive group that may be used: 1) The time location where theminimum or maximum value of the feature is located, 2) The peak to peakamplitude of the feature (and how many samples), 3) the direction of theapparent dip angle with respect to the tool (or borehole).

FIG. 6B shows the calculation of the apparent dip angle. The dip may bedetermined by fitting a function, for example the function representedby the line 601, superimposed on the Features of the data with adjacentsectors Region of Interest. The image trace of desired imaging featuresof interest such as bedding boundaries or other subsurface structureboundaries will most often cross boreholes with a sinusoidal behavior.Bedding boundaries will display as a sinusoid. This sinusoidal behaviorof the Features (i.e., 601) allows a data compression related algorithmsuch as the 2-D Discrete Cosine Transform (DCT) to operate with goodresults, and for the apparent dip angle to fall out of the compressionprocess when energy of the transform terms is minimized.

Transformation is illustrated at 409 in FIG. 4. The 2-D Discrete CosineTransform (DCT) has been used as a method of energy localization. The1-D DCT for a vector of length N is given by equation (1), for the rangem to N-1. The DCT will be calculated in the sector direction then in thetime or depth dimension.

$\begin{matrix}\begin{Bmatrix}{{y(m)} = {\sqrt{\frac{2}{N}}{\sum\limits_{k = 0}^{N - 1}{{x(k)}\cos\frac{\left( {{2k} + 1} \right)m\;\pi}{2N}}}}} & {m = 0} \\{{y(m)} = {\sqrt{\frac{2}{N}}{\sum\limits_{k = 0}^{N - 1}{{x(k)}\cos\frac{\left( {{2k} + 1} \right)m\;\pi}{2N}}}}} & {m \neq 0}\end{Bmatrix} & (1)\end{matrix}$

Since the density data range from 1.5 g/cc to 3.00 g/cc (within a fairlynarrow range), the Discrete Cosine (DC) value may be replaced by thedifference between the DC value and its estimate. The estimate value ofthe DC is based on the size of the data.

FIG. 7 illustrates the estimate DC value of the 2-D DCT. The x-axisshows the size of the data. The y-axis shows the estimate DC value ofthe 2-D DCT.

The output matrix of DCT coefficients contains integers. The signalenergy lies at relatively low frequencies; these appear in the upperleft corner of the DCT (Table 1). The lower right values representhigher frequencies, and are often small enough to be neglected withlittle visible distortion. Table 1 shows how the DCT operates on the 8by 8 matrix.

TABLE 1 (was Table 2): DCT Coefficients 92 3 −9 −7 3 −1 0 2 −39 −85 1217 −2 2 4 2 −84 62 1 −18 3 4 −5 5 −52 −36 −10 14 −10 4 −2 0 −86 −40 −49−7 17 −6 −2 6 −62 65 −12 −2 3 −8 −2 0 −17 14 −36 17 −11 3 3 −1 −54 32 −9−9 22 0 1 3

Quantization is illustrated at 411 in FIG. 4. There is a tradeoffbetween image quality and the degree of quantization. A largequantization step size can produce unacceptably large image distortion.This effect is similar to quantizing Fourier series coefficients toocoarsely; large distortions would result. Unfortunately, finerquantization leads to lower compression ratios. The question is how toquantize the DCT coefficients most efficiently. Because of humaneyesight's natural high frequency roll-off, these frequencies play aless important role than low frequencies. This lets JPEG use a muchhigher step size for the high frequency coefficients, with littlenoticeable image deterioration.

The quantization matrix is the 8 by 8 matrix of step sizes (sometimescalled quantum)—one element for each DCT coefficient. It is usuallysymmetric. Step sizes will be small in the upper left (low frequencies),and large in the upper right (high frequencies); a step size of 1 is themost precise. The quantizer divides the DCT coefficient by itscorresponding quantum and then rounds to the nearest integer. Largequantization matrix coefficients drive small coefficients down to zero.The result: many high frequency coefficients become zero, and thereforeeasier to code. The low frequency coefficients undergo only minoradjustment. By choosing parameterization of the matrices efficiently,zeros among the high frequency coefficients leads to efficientcompression. Table 2 shows the quantization matrix.

TABLE 2 The Quantization Matrix 3 4 5 6 7 8 9 10 4 5 6 7 8 9 10 11 5 6 78 9 10 11 12 6 7 8 9 10 11 12 13 7 8 9 10 11 12 13 14 8 9 10 11 12 13 1415 9 10 11 12 13 14 15 16 10 11 12 13 14 15 16 17

TABLE 4 The quantized Data 30 0 −1 0 0 0 0 0 −7 −8 1 1 0 0 0 0 −12 6 0−1 0 0 0 0 −5 −3 0 0 0 0 0 0 −7 −3 3 0 0 0 0 0 −4 4 0 0 0 0 0 0 −1 0 −10 0 0 0 0 −3 1 0 0 0 0 0 0

Table 3 shows the quantized data of given in Table 1. Quantization hasbeen done into two steps: 1) Dynamic range reduction. 2) EZW (EmbeddedZerotree Wavelet Encoder). A linear quantizer has been used. However, insome cases some of the coefficients have a very big value relative toother coefficient values. Most probably those values will be located inthe first column of data based on the property of the 2-D DCT. Thenumber of the elements in the first column depends on the data size,however for a data size of length less than 360, it appears that ifthere is a big coefficient they have a big chance to appear in the firsteight element of the first column. So the integer value of the first fewcoefficients will be coded separately and they will be replaced by thedifference between the actual value and the coded value. The rest of thedata will be multiplied by 100 and converted into integers, and then itwill be quantized according to the EZW method. FIG. 8 shows how the EZWmethod scans the image. See Embedded Image Coding Using Zerotrees ofWavelet Coefficients, Shapiro, J. M., IEEE Transactions on SignalProcessing, Vol. 41. No 12, December 1993, or N. M. Rajpoot and R. G.Wilson, Progressive Image Coding using Augmented Zerotrees of WaveletCoefficients, Research Report CS-RR-350, Department of Computer Science,University of Warwick (UK), September 1998.

The image will be scanned in multiple passes. In every pass the elementswill be compared to a threshold. If the element values exceed thethreshold (e.g. the threshold could equal 20, but this will be dataand/or area dependent) it will be replaced by the actual value of theelements minus 1.5 times the threshold. Then the threshold will bereduced in a predetermined order and more passes will be done until themaximum allowable size of the data will be achieved.

The quantized data may be coded into different formats at 423 in FIG. 4depending on whether an image or only selected parameters (e.g. DipAngle, Feature depth, and other associated characteristics) are to betransmitted to the surface. The first format is for dip angletransmission (e.g., from 419 to 421 in FIG. 4); the second format is forimage transmission (as illustrated from 411 to 421 in FIG. 4). Anexample for Dip Angle parameters may be coded as follows: The buffersize will be set to 6 bytes. The first bit as zero indicates the thatthe packet has dip angle data, the next 17 bits indicate the time wherethe minimum of the feature has occur, the next 8 bits indicate theamplitude of the feature, and the next three bits indicate the sectorwhere the maximum has occurred. After data are coded and formatted, thedata may be further formatted and compressing and encoded such that theencoded, compressed values are applied (425 FIG. 3) to a selectedposition in a telemetry format for transmission (413 FIG. 4) to thesurface recording unit.

If the data are for an image, the first bit of the code will be ‘1’indicating that the image has data followed by 17 bits for the time ofthe first data, followed by some overhead, then the data. The data willbe coded into parts: 1) The Dynamic range reduction Code; 2) The EZWCode. The Dynamic Range Reduction Code: the first eight data pointsassigning three bits for every point. If the data point has a maximumvalue it indicates that the next value should be added to the currentvalue to the actual data value. The output of the EZW is one of the foursymbols (P, N, Z, and T). Where is the symbol T has more probability tobe found in the data, T is going to be assigned to 0, Z is going to beassigned 10, N is going to be assigned 110, and P is going to beassigned 111.

The EZW (Embedded Zerotree Wavelet Encoder) may be inefficient when itis used with DCT coefficients. However, by rearranging the DCT blocks inspecific order, it is possible to use EZW with DCT in a very efficientway, and thereby further, to transmit data in multiple resolutions sothat a plurality of resolutions of the data may be transmitted andrecombined according to the ultimate resolution desired. The DiscreteCosine Transform may be used for multi-resolution image compression tocompress and decompose the Image with low computations compared towavelets. It allows for the transmission of one or more resolutionlevels of the compressed image in a noise channel, and possibly losingonly a resolution level or partial resolution level due to noise insteadof losing the entire image. Also the images and/or compressed images canbe stored in the memory (e.g., in flash memory) downhole in highresolution format, so the user can transmit only the resolution orplurality of resolutions needed or desired per image based on thesetting for the algorithm parameters.

Matrix Rearrangement: the input image will be dividing into N by Nblocks, and the DCT will be used on every block. The DC coefficient ofevery block will be replaced by the difference between the DCcoefficient and its estimate value. The new DCT matrixes will berearrange into new matrix suitable for LZW. Table 5 and Table 6 show twoblocks of DCT matrix. The two block of the DCT will be arranged into anew matrix as following.

TABLE 5 The DCT of two blocks 40 2 −1 −3 0 0 0 0 20 −8 1 1 0 0 0 0 −12 52 −1 0 0 0 0 −2 11 5 0 0 0 0 0 10 14 0 0 0 0 0 0 −3 4 1 0 0 0 0 0 14 2 01 0 0 0 0 6 3 1 0 0 0 0 0

The first column of the DCT block will become the first row on the newif the dimensions of the new matrix allows, if not it will start fromthe next row of the new matrix. The second columns of the DCT blocks ofthe new matrix as above until the all the DCT blocks has been scanned.The new matrix may not be symmetric but the LSW can work in nonsymmetric matrix and still give compression ration higher than the JPEG.Symmetric matrix gives much higher compression ratio. Table 6 shows thenew matrix after rotation for two DCT blocks.

The image will be scanned in multiple passes in every pass the everyelement will be indicated if it is above a threshold, the threshold ifit is above the threshold it will be replaced by the actual value of theelements minus 1.5 times the threshold. The threshold will be reduced inpredetermined order and more pass will be done until the maximumallowable size of the data will be achieved.

TABLE 6 The DCT of the new matrix after rearrangement of the DCT blocks−15 −7 −12 −5 −7 −4 −1 −3 5 20 −12 −2 10 −3 14 6 0 −8 6 −3 −3 4 0 1 2 −85 11 14 4 2 3 −1 1 0 0 3 0 −1 0 −1 1 2 5 0 1 0 1 0 1 −1 0 0 0 0 0 −3 1−1 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Reconstruction Module: The second module runs at the surface. The modulereceives block/blocks of binary number that are transmitted and a copyof the selected parameters. The second module may be implemented, forexample, as an executable file using Matlab.

The output of the second module may be an ASCII file that represents theimage at time bases. The second module encodes the received block/blocksof data and determines if the data represents an image or represents theparameters of the apparent dip angle. If the received blocked is animage, the second module generates an ASCII file. The first row of theASCII file represents the time of every reading in the next eightcolumns. The first column has the time (hh:mm:ss), and the second columnto the ninth column has the density data that represent the image.

Data Reconstruction: The executable file at the surface receives thedata packet and the parameter which has been down linked. If the firstbit is zero it generates the Apparent Dip angle parameters. If the firstbit of the data is one it extracts the image. FIG. 9 shows raw datawhich has been compressed with three levels of compression using amulti-resolution compression algorithm like the Discrete CosineTransform. FIG. 10 shows the data at one resolution that has beencompressed with a relatively high compression ratio (with a compressionof 300:1). FIG. 11 shows the data has been compressed with a mediumcompression ratio (with a compression of 150:1). FIG. 12 shows the datahas been compressed with a relatively low compression ratio (acompression of 100:1 or three times as much data as for FIG. 10).

Display Module: The image represents structure of the earth so it may bemore convenient to color map the image with “earth tone” colors. Becauseof human eyesight's natural high frequency roll-off, these frequenciesplay a less important role than low frequencies. The density datarepresent low resolution images, so it may be more convenient to smooththe image in the depth direction before displaying it. Also azimuthallysectored log data may be interpolated to generate a smooth image in boththe depth direction and the azimuthally direction. A suitable linearinterpolation and color map scheme may be implemented. Bed boundarieswill display as sine waves.

Error Analysis: One of the most challenging problems in imagecompression is to measure the quality of image in terms of error. Evenmost of the common error analysis gives an indication to the amount oferror in the image, it is necessary that an image with lower errormeasurement looks better than image with bigger error measurement.

Examples of two criteria that have been used to measure the error in theimage as shown in equation 2 and equation 3.

$\begin{matrix}{{acc\_ Error} = \sqrt{\frac{\sum\limits_{i}^{N}{\sum\limits_{j}^{M}\left( {{{Raw}\;{Data}} - {Reconstructed}} \right)^{2}}}{\sum\limits_{i}^{N}{\sum\limits_{j}^{M}({RawData})^{2}}}}} & (2) \\{{rms\_ Error} = \frac{\sqrt{\sum\limits_{i}^{N}{\sum\limits_{j}^{M}\left( {{RawData} - {Reconstructed}} \right)^{2}}}}{NM}} & (3)\end{matrix}$

The error measurements do not measure the image quality very precisely.FIG. 13 shows the acc error versus the compression ratio and FIG. 14shows the Root-mean-square (RMS) error versus the compression ratio. Theuser's needs change according to the drilling conditions. In order toconfigure the tool according to the user's needs the tool has to beconfigured either on the surface or on the fly by downlink.

On the surface: A parameter table may be updated on the surface. Incases where the parameter table has not been updated the system will usedefault or preset values.

Down Link: In order to configure the system on the fly, down linkcommands are required. In cases where the tool has not been configuredat the surface, a new configuration may be sent by a down link command.The data may be immediately available for use. The availableconfigurations options are as in the following examples:

The portion of density data that needs to be transmitted:

-   -   a. The last block from the current location of the buffer; the        block size is 8*128    -   b. the last N blocks    -   c. The entire image    -   d. The region/regions where the last feature/features has/have        been located    -   e. The parameters or characteristics of the Apparent Dip Angle

The level of compressed for the entire image

-   -   f. Low compression (e.g. 60:1)    -   g. Medium Compression (e.g. 90:1)    -   h. High Compression (e.g. 150:1)

The method of data transmission

-   -   i. On demand i.e. downlink    -   j. Periodic function generated by the master. The period        function will be activated/deactivated on the surface and/or        configure by a down link command. The period function commands        are:        -   i. Every power on transmit the last block of data        -   ii. Every power on transmit the last region of interest        -   iii. Every power on transmit the parameters of the apparent            dip angle        -   iv. Every power on transmit a combination from the above        -   v. When the image is available (i.e. every 1280 sec)        -   vi. When a region of interest is available i.e. check every            1280 sec        -   vii. When the parameters of the apparent dip angle available            i.e. every 320 sec.

As illustrated in FIG. 15 the invention provides method and apparatusfor logging an earth formation and acquiring subsurface informationwherein a logging tool is conveyed in borehole 1502 to obtain parametersof interest 1504. The parameters of interest obtained may be density,acoustic, magnetic or electrical values as known in the art. Asnecessary, a standoff and azimuth associated with the measurements areobtained 1506 and corrections applied. The corrected data may befiltered and/or smoothed as necessary. The parameters of interestassociated with azimuthal sectors are formed into a plurality of CostFunctions 1508 from which Regions of Interest are determined 1510 toresolve characteristics of the Features of interest within the Regions.Also, for initial delineation of Regions of Interest and associatedFeatures, Cost Functions from a plurality of sectors may be combined toefficiently obtain prospective areas of the Cost Functions. The Featuresmay be determined to obtain time or depth positions of bed boundariesand the Dip Angle 1512 of the borehole relative to subsurfacestructures, as well as the orientation of the logging equipment andsubsurface structure. Characteristics of the Features include time,depth, dip of subsurface structure. The Regions of Interest may begenerally characterized according to the behavior of the Regions in theneighborhood of various subsurface features. For example, a thin-bedtype response may be characterized as shown in FIG. 5B where the Regionof Interest spans two positive amplitude local maxima with a localminimum between the maxima. This is further illustrated in FIG. 5C byRegion of Interest 501. FIG. 5C illustrates four types of Regions ofInterest that have Features that may be identified, and illustrates howthe Features are disposed about an arbitrary reference 509. The inverseof the 501 situation is illustrated by Region of Interest 503 where twominima bracket a maximum. Region of Interest 505 illustrates thesituation where a Feature exists between in an area of maximum valueswhich has a relatively fast transition to minimum values. Region ofInterest 507 illustrates the situation where a Feature exists between inan area of minimum values which has a relatively fast transition tomaximum values.

As illustrated in FIG. 16 the invention provides method and apparatusfor logging an earth formation and obtaining a plurality of parametersof interest of an earth formation 1602 penetrated by a wellbore atazimuthally spaced apart positions in the wellbore and defining aplurality of azimuthal sectors associated with the parameters ofinterest. The parameters of interest obtained may be density, acoustic,magnetic or electrical values as known in the art. Pluralities of CostFunctions 1604 are determined from the plurality of parameters ofinterest associated with the azimuthal sectors. Features are determinedwithin the plurality of Cost Functions 1606. A Dip Angle is determinedfrom the Features 1608 determined from the Cost Functions. The Dip Angleis then encoded 1610 and transmitted to the surface recording unit forfurther uses.

As illustrated in FIG. 17 the invention provides method and apparatusfor logging an earth formation and acquiring subsurface informationwherein a logging tool is conveyed in borehole 1702 to obtain parametersof interest 1704. The parameters of interest obtained may be density,acoustic, magnetic or electrical values as known in the art. Asnecessary, a standoff and azimuth associated with the measurements areobtained 1706 and corrections applied. The corrected data may befiltered and/or smoothed as necessary. At this point, the parameters ofinterest associated with azimuthal sectors may be encoded at a pluralityof resolutions using a Discrete Cosine Transform to obtain encoded data1708 that may be transmitted to the surface 1710. FIGS. 10, 11 and 12demonstrate the recombination of the plurality of resolutions as thecompression changes from 300:1 in FIG. 10, 150:1 in FIG. 11 and finally100:1 as the third input of resolution is combined.

In another aspect, the present invention provides for transmitting dataas computed values of one or more downhole parameters of interest orcharacteristics based at least in part on the dip angle and/ororientation measurements. As it is known, real time imaging and apparentdip angle calculations are important parameters for real-timegeosteering of the drilling assembly and for real-time determination offormation parameters. The data communication between the downhole andsurface equipment typically has limited bandwidth, particularly whendrilling mud is utilized as the transmission channel. In one aspect ofthe present invention, real-time apparent dip is calculated downhole(i.e. by the downhole processor) and transmitted uphole, which utilize afew bits of data. This method is useful because calculations useddownhole can be extensive.

As noted above, the parameters of interest apparent dip angle and/ororientation can be used to define regions of interest (i.e. featureextraction). Data and/or computed parameters relating to formation canthen be transmitted when the dip and/or orientation meet a certaincriteria or threshold. In this manner, the data relating to the regionof interest is compressed and sent to the surface. This method cansignificantly increase the ability to compress data and still providedesired resolution. The apparent dip angle calculations may be based onthe region of interest. Also, the calculations of the apparent dip anglebased on feature extraction can eliminate uncertainties oflocal-minimum, local maximum, window size, etc., thereby improving theaccuracy of the computed values.

Thus, according to one aspect of the invention, the system determinesthe dip angle and/or tool orientation downhole, selects the dip angleand/or tool orientation that will be sent to the surface, and then sendsthe data relating to the dip angle and other parameters to the surface.The dip and/or orientation may be sent to the surface if it covers aregion of interest and based on predetermined or selected criteria. Forexample, the predetermined criteria may be that dips above ten (10)degrees define regions of interest. Thus, regions with dips less thanten (10) degrees may be of no interest. For such regions, selectedsensors and/or processing of data may be turned off, and turned on whenthe dip angle meets the criteria. In this manner dip and orientation maybe used to select what data (from one or more downhole sensors or tools)to send to the surface. Other examples may be that the system may beprogrammed or configured to (i) send data from all or selected sensorswhen a dip is present; (ii) send only selected data, for example, gammaray data, if no dips are present; (iii) send gamma ray and resistivitydata when dip are above a certain angle; and (iv) send data for selectedor all sensors when the dip angle meets the selected criteria. Thus, ingeneral, the downhole calculations of dip angle and orientation may beused as a base or criterion (whole or in part) to determine what type ofdata and how much of the data to transmit to the surface.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all variations within the scopeand spirit of the appended claims be embraced by the foregoingdisclosure.

1. A method of logging an earth formation comprising: determiningdownhole a first parameter of interest that is one of a dip angle of abed and an orientation of a bed using a sensor; determining when thefirst parameter of interest meets a selected criterion using aprocessor; using the processor to transmit data relating to at least oneadditional parameter of interest relating to the earth formation whenthe first parameter of interest meets the selected criterion; andstoring the transmitted data to a suitable storage medium.
 2. The methodof claim 1, wherein the first parameter of interest is an apparent dipangle and the criterion is that the dip angle is at least ten (10)degrees.
 3. The method of claim 1, wherein the at least one additionalparameter is at least one of i) a gamma ray measurement; (ii) aresistivity measurement; (iii) an acoustic measurement; and (iv) anuclear magnetic resonance measurement.
 4. The method of claim 3,wherein the first parameter of interest is the dip angle and furthercomprising transmitting data related to gamma ray measurements only whenthe dip angle is below a threshold.
 5. The method of claim 1, whereinthe first parameter of interest is the dip angle and further comprisingtransmitting data relating to a plurality of downhole parameters and thedip angle when the dip angle meets the selected criterion.
 6. The methodof claim 1 wherein the additional parameter of interest is selected fromthe group consisting of: i) density, ii) porosity, iii) electricalresistivity, iv) a nuclear magnetic resonance property, and v) acousticreflectance.
 7. The method of claim 1 further comprising using theprocessor to encode the first parameter of interest and transmit thefirst parameter of interest to a surface recording unit.
 8. The methodof claim 7 wherein encoding the first parameter of interest furthercomprises compressing the first parameter of interest using a transformfor multi-resolution image compression.
 9. A downhole tool for use in awellbore, comprising: a sensor configured to make measurements relatingto a dip angle; a plurality of sensors configured to make measurementsrelating to parameters of an earth formation traversed by the wellbore;and a processor configured to determine the dip angle and transmit datarelating to at least one sensor in the plurality of sensors when thedetermined dip angle meets a selected criterion.
 10. The tool of claim9, wherein the plurality of sensors includes at least one of (i) a gammaray sensor; (ii) a resistivity sensor; (iii) an acoustic sensor; (iv) anuclear magnetic resonance (NMR) sensor; and (v) a nuclear prioritysensor.
 11. The tool of claim 9, wherein the processor is configured totransmit the data relating to at least one sensor in the plurality ofsensors when the dip angle is greater than ten (10) degrees.
 12. Thetool of claim 9, wherein the processor is configured to transmit gammaray data when the dip angle does not meet the selected criterion. 13.The tool of claim 9, wherein the processor is further configured toencode the dip angle and transmit the dip angle to the surface recordingunit.
 14. The tool of claim 13 wherein the processor is furtherconfigured to compress the dip angle using a transform formulti-resolution image compression to encode the dip angle.